Control of Resin Curing

ABSTRACT

Systems and methods of treating a zone of a subterranean formation penetrated by a wellbore are described. A composition may include a first solution including at least one amine containing resin; and citraconic anhydride. The composition may also include a second solution mixed with the first solution, where the second solution includes at least one epoxide containing resin. Methods may include providing the treatment fluid to a subterranean formation.

FIELD

The disclosure generally relates to producing oil or gas from asubterranean formation. More specifically, the disclosure relates tocompositions and methods for use in treating a subterranean formationfor controlling the migration of particulates, such as formation sandand fines.

BACKGROUND

Oil or gas is obtained from a subterranean formation by drilling awellbore that penetrates a hydrocarbon-bearing formation. It isdesirable to maximize both the rate of flow and the overall amount offlow of hydrocarbon from the subterranean formation to the surface.

One way that the rate of hydrocarbon flow and the overall amount ofhydrocarbon flow can be reduced is by fines production or sand migrationin the formation or by precipitation. The relatively high velocity inthe permeable matrix of the subterranean formation near the wellbore issometimes sufficient to mobilize particulates. These particulates can becarried and then plug flow channels in the formation, a proppant pack,or a gravel pack. It is desirable to minimize fines or sand migration,since such particulates block flow paths, choking the potentialproduction of the well. In addition, such particulates can damagedownhole and surface equipment, such as screens, pumps, flow lines,storage facilities, etc.

Wellbores often penetrate subterranean formations that containunconsolidated particulates that may migrate when oil, gas, water, orother fluids are produced or flowed back from the subterraneanformation.

Devices such as screens and slotted liners are often used to providesupport for these unconsolidated formations to inhibit formationcollapse. Usually, the annulus around the support device is gravelpacked to reduce the presence of voids between the device and theborehole. Typically, such gravel packing operations involve the pumpingand placement of a quantity of a desired size of particulate materialinto the annulus between the tubular device and the borehole of thewellbore. Gravel packing forms a filtration bed near the wellbore thatacts as a physical barrier to the transport of unconsolidated formationfines with the production of hydrocarbons. These support devices providesupport for the wellbore and gravel packing and prevent some fines fromentering the hydrocarbon flow into the well.

Some types of screens are adapted to be expanded to contact the wellborewall either with or without gravel packing. It is, however, impossibleto eliminate all voids between the screen and the wellbore wall. Finesfill these voids blocking flow and in some instances fines flowingthrough these voids erode the screen, destroying its effectiveness.

One common type of gravel packing operation involves placing a gravelpack screen in the wellbore and packing the surrounding annulus betweenthe screen and the wellbore with gravel of a specific mesh size designedto prevent the passage of formation sand or fines. The gravel packscreen is generally a filter assembly used to retain the gravel placedduring a gravel pack operation. A wide range of sizes and screenconfigurations are available to suit the characteristics of the gravelpack sand. Similarly, a wide range of gravel sizes is available to suitthe characteristics of the unconsolidated or poorly consolidatedparticulates in the subterranean formation. The resulting structurepresents a barrier to migrating sand from the formation while stillpermitting fluid flow.

Gravel packs can be time consuming and expensive to install. Due to thetime and expense needed, it is sometimes desirable to place a screenwithout the gravel and, particularly in cases in which an expandablescreen is being placed, it may be unrealistic to place a bed of gravelbetween the expandable screen and the wellbore. Even in circumstances inwhich it is practical to place a screen without a gravel pack, it isoften difficult to determine an appropriate screen size to use asformation sands tend to have a wide distribution of sand grain sizes.When small quantities of sand are allowed to flow through a screen,screen erosion becomes a significant concern. As a result, the placementof gravel as well as the screen is often necessary to control theformation sands.

An expandable screen is often installed to maintain the diameter of thewellbore for ease of access at a later time by eliminating installationof conventional screens, gravel placement, and other equipment. However,the ability to provide universal screen mesh that can handle wideparticle size distribution of formation sand is unrealistic, if notimpossible.

Another method used to control particulates in unconsolidated formationsinvolves consolidating a subterranean producing zone into hard,permeable masses. Consolidation of a subterranean formation zone ofteninvolves applying a resin followed by a spacer fluid and then acatalyst. Such resin application may be problematic when, for example,an insufficient amount of spacer fluid is used between the applicationof the resin and the application of the external catalyst. The resin maycome into contact with the external catalyst in the wellbore itselfrather than in the unconsolidated subterranean producing zone. Whenresin is contacted with an external catalyst, an exothermic reactionoccurs that may result in rapid polymerization, potentially damaging theformation by plugging the pore channels, halting pumping when thewellbore is plugged with solid material, or resulting in a downholeexplosion as a result of the heat of polymerization. Also, theseconventional processes are not practical to treat long intervals ofunconsolidated regions due to the difficulty in determining whether theentire interval has been successfully treated with both the resin andthe external catalyst. Gravel packing is a costly operation and resinplacement can sometimes damage the formation.

As indicated, a variety of chemical treatments are available forcontrolling fines migration. Resin treatments are widely accepted. Resinsystems, however, fail to achieve deep penetration due to high viscosityand premature curing. The major cause behind the premature curing inmajority of resin systems is the immediate temperature sensitivecrosslinking reaction between epoxy and amine groups.

In addition to the unconsolidated formation sands often found insubterranean formations, particulate materials are often introduced intosubterranean zones in conjunction with conductivity enhancing operationsand sand control operations. Conductivity enhancing and sand controloperations may be performed as individual treatments, or may be combinedwhere desired.

Preventing formation sand and fines from migrating from anunconsolidated formation has always been a challenge. While previouslyknown treatment methods for unconsolidated formation provide improvedparticulate control, multiple treatment steps that are time consumingand expensive are usually required. Therefore, it is desirable todevelop relatively simple and relatively inexpensive treatmentcompositions and methods to improve or maintain the rate of fluid flowwhile reducing particulate migration.

BRIEF DESCRIPTION OF THE DRAWINGS

The accompanying drawings, which are included to provide a furtherunderstanding of the disclosure and are incorporated in and constitute apart of this specification, illustrate preferred embodiments of thedisclosure and together with the detailed description serve to explainthe principles of the disclosure. In the drawings:

FIG. 1 is a diagram illustrating an example of a fracturing system thatmay be used in accordance with certain embodiments of the presentdisclosure.

FIG. 2 is a diagram illustrating an example of a subterranean formationin which a fracturing operation may be performed in accordance withcertain embodiments of the present disclosure.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Systems and methods are described for resin curing control in treatmentof a subterranean formation. In certain embodiments, a chemicalcomponent may delay crosslinking reaction between amine and epoxy groupsin a treatment fluid. Certain embodiments may include an aminecontaining resin, an epoxide containing resin and citraconic anhydride.Embodiments may improve penetration into a formation. The systems andmethods described herein may be applied in oilfield drillingapplications or for other situations where uses of resin materials, inor out of a wellbore, are advantageous. The examples described hereinrelate to resin treatments for illustrative purposes only. In alternateembodiments, the systems and methods may be used wherever use of resinis desirable.

DEFINITIONS AND USAGES General Interpretation

The words or terms used herein have their plain, ordinary meaning in thefield of this disclosure, except to the extent explicitly and clearlydefined in this disclosure or unless the specific context otherwiserequires a different meaning.

If there is any conflict in the usages of a word or term in thisdisclosure and one or more patent(s) or other documents that may beincorporated by reference, the definitions that are consistent with thisspecification should be adopted.

The words “comprising,” “containing,” “including,” “having,” and allgrammatical variations thereof are intended to have an open,non-limiting meaning. For example, a composition comprising a componentdoes not exclude it from having additional components, an apparatuscomprising a part does not exclude it from having additional parts, anda method having a step does not exclude it having additional steps. Whensuch terms are used, the compositions, apparatuses, and methods that“consist essentially of” or “consist of” the specified components,parts, and steps are specifically included and disclosed.

The indefinite articles “a” or “an” mean one or more than one of thecomponent, part, or step that the article introduces.

Whenever a numerical range of degree or measurement with a lower limitand an upper limit is disclosed, any number and any range falling withinthe range is also intended to be specifically disclosed. For example,every range of values (in the form “from a to b,” or “from about a toabout b,” or “from about a to b,” “from approximately a to b,” and anysimilar expressions, where “a” and “b” represent numerical values ofdegree or measurement) is to be understood to set forth every number andrange encompassed within the broader range of values.

It should be understood that algebraic variables and other scientificsymbols used herein are selected arbitrarily or according to convention.Other algebraic variables can be used.

Subterranean Formations and Oil and Gas Reservoirs

In the context of production from a well, “oil” and “gas” are understoodto refer to crude oil and natural gas, respectively. Oil and gas arenaturally occurring hydrocarbons in certain subterranean formations.

A “subterranean formation” is a body of rock that has sufficientlydistinctive characteristics and is sufficiently continuous forgeologists to describe, map, and name it.

A subterranean formation having a sufficient porosity and permeabilityto store and transmit fluids is sometimes referred to as a “reservoir.”

A subterranean formation containing oil or gas may be located under landor under the seabed off shore. Oil and gas reservoirs are typicallylocated in the range of a few hundred feet (shallow reservoirs) to a fewtens of thousands of feet (ultra-deep reservoirs) below the surface ofthe land or seabed.

In geology, rock or stone is a naturally occurring solid aggregate ofminerals or mineraloids. The Earth's outer solid layer, the lithosphere,is made of rock. Three major groups of rocks are igneous, sedimentary,and metamorphic. The vast majority of reservoir rocks are sedimentaryrocks, but highly fractured igneous and metamorphic rocks can sometimesbe reservoirs.

A consolidated formation is a geologic material for which the particlesare stratified (layered), cemented, or firmly packed together (hardrock); usually occurring at a depth below the ground surface. Anunconsolidated formation is a sediment that is loosely arranged orunstratified (not in layers) or whose particles are not cementedtogether (soft rock); occurring either at the ground surface or at adepth below the surface. In an unconsolidated or weakly consolidatedformation, some particulates are insufficiently bonded in the formationto withstand the forces produced by the production or flowback of fluidsthrough the matrix of the formation.

As used herein, a subterranean formation having greater than about 50%by weight of inorganic siliceous materials (e.g., sandstone) is referredto as a “sandstone formation.”

There are conventional and non-conventional types of reservoirs. In aconventional reservoir, the hydrocarbons flow to the wellbore in amanner that can be characterized by flow through permeable media, wherethe permeability may or may not have been altered near the wellbore, orflow through permeable media to a permeable (conductive), bi-wingfracture placed in the formation. A conventional reservoir wouldtypically have a permeability greater than about 1 milliDarcy(equivalent to about 1,000 microDarcy).

Wells, Well Servicing, Treatment Fluids, and Treatment Zones

To produce oil or gas from a reservoir, a wellbore is drilled into asubterranean formation, which may be the reservoir or adjacent to thereservoir. Typically, a wellbore of a well must be drilled hundreds orthousands of feet into the earth to reach a hydrocarbon-bearingformation.

Generally, well services include a wide variety of operations that maybe performed in oil, gas, geothermal, or water wells, such as drilling,cementing, completion, and intervention. Well services are designed tofacilitate or enhance the production of desirable fluids such as oil orgas from or through a subterranean formation. A well service usuallyinvolves introducing a fluid into a well.

A “well” includes a wellhead and at least one wellbore from the wellheadpenetrating the earth. The “wellhead” is the surface termination of awellbore, which surface may be on land or on a seabed.

A “well site” is the geographical location of a wellhead of a well. Itmay include related facilities, such as a tank battery, separators,compressor stations, heating or other equipment, and fluid pits. Ifoffshore, a well site can include a platform.

The “wellbore” refers to the drilled hole, including any cased oruncased portions of the well or any other tubulars in the well. The“borehole” usually refers to the inside wellbore wall, that is, the rocksurface or wall that bounds the drilled hole. A wellbore can haveportions that are vertical, horizontal, or anything in between, and itcan have portions that are straight, curved, or branched. As usedherein, “uphole,” “downhole,” and similar terms are relative to thedirection of the wellhead, regardless of whether a wellbore portion isvertical or horizontal.

A wellbore can be used as a production or injection wellbore. Aproduction wellbore is used to produce hydrocarbons from the reservoir.An injection wellbore is used to inject a fluid, e.g., liquid water orsteam, to drive oil or gas to a production wellbore.

As used herein, introducing “into a well” means introducing at leastinto and through the wellhead. According to various techniques known inthe art, tubulars, equipment, tools, or fluids can be directed from thewellhead into any desired portion of the wellbore.

As used herein, the term “annulus” means the space between two generallycylindrical objects, one inside the other. The objects can be concentricor eccentric. Without limitation, one of the objects can be a tubularand the other object can be an enclosed conduit. The enclosed conduitcan be a wellbore or borehole or it can be another tubular. Thefollowing are some non-limiting examples illustrating some situations inwhich an annulus can exist. Referring to an oil, gas, or water well, inan open hole well, the space between the outside of a tubing string andthe borehole of the wellbore is an annulus. In a cased hole, the spacebetween the outside of the casing and the borehole is an annulus. Inaddition, in a cased hole there may be an annulus between the outsidecylindrical portion of a tubular such as a production tubing string andthe inside cylindrical portion of the casing. An annulus can be a spacethrough which a fluid can flow or it can be filled with a material orobject that blocks fluid flow, such as a packing element. Unlessotherwise clear from the context, as used herein an “annulus” is a spacethrough which a fluid can flow.

As used herein, a “fluid” broadly refers to any fluid adapted to beintroduced into a well for any purpose. A fluid can be, for example, adrilling fluid, a setting composition, a treatment fluid, or a spacerfluid. If a fluid is to be used in a relatively small volume, forexample less than about 200 barrels (about 8,400 US gallons or about 32m³), it is sometimes referred to as a wash, dump, slug, or pill.

As used herein, the word “treatment” refers to any treatment forchanging a condition of a portion of a wellbore, or a subterraneanformation adjacent a wellbore; however, the word “treatment” does notnecessarily imply any particular treatment purpose. A treatment usuallyinvolves introducing a fluid for the treatment, in which case it may bereferred to as a treatment fluid, into a well. As used herein, a“treatment fluid” is a fluid used in a treatment. The word “treatment”in the term “treatment fluid” does not necessarily imply any particulartreatment or action by the fluid.

A “zone” refers to an interval of rock along a wellbore that isdifferentiated from uphole and downhole zones based on hydrocarboncontent or other features, such as permeability, composition,perforations or other fluid communication with the wellbore, faults, orfractures. A zone of a wellbore that penetrates a hydrocarbon-bearingzone that is capable of producing hydrocarbon is referred to as a“production zone.” A “treatment zone” refers to an interval of rockalong a wellbore into which a fluid is directed to flow from thewellbore. As used herein, “into a treatment zone” means into and throughthe wellhead and, additionally, through the wellbore and into thetreatment zone.

The term “damage” as used herein regarding a subterranean formationrefers to undesirable deposits in a subterranean formation that mayreduce its permeability. Scale, skin, gel residue, hydrates, and resindamage, are contemplated by this term.

The term “sand control device” is used generically herein and is meantto include and cover all types of similar structures which are commonlyused in gravel pack well completions which permit flow of fluids throughthe “screen” while blocking the flow of particulates (e.g.,commercially-available screens; slotted or perforated liners or pipes;sintered-metal screens; sintered-sized, mesh screens; screened pipes;pre-packed screens, radially-expandable screens or liners; orcombinations thereof).

Generally, the greater the depth of the formation, the higher the statictemperature and pressure of the formation. Initially, the staticpressure equals the initial pressure in the formation before production.After production begins, the static pressure approaches the averagereservoir pressure.

Deviated wells are wellbores inclined at various angles to the vertical.Complex wells include inclined wellbores in high-temperature orhigh-pressure downhole conditions.

A “design” refers to the estimate or measure of one or more parametersplanned or expected for a particular fluid or stage of a well service ortreatment. For example, a fluid can be designed to have components thatprovide a minimum density or viscosity for at least a specified timeunder expected downhole conditions. A well service may include designparameters such as fluid volume to be pumped, required pumping time fora treatment, or the shear conditions of the pumping.

The term “design temperature” refers to an estimate or measurement ofthe actual temperature at the downhole environment during the time of atreatment. For example, the design temperature for a well treatmenttakes into account not only the bottom hole static temperature (“BHST”),but also the effect of the temperature of the fluid on the BHST duringtreatment. The design temperature for a fluid or treatment is sometimesreferred to as the bottom hole circulation temperature (“BHCT”). Becausefluids may be considerably cooler than BHST, the difference between thetwo temperatures can be quite large. Ultimately, if left undisturbed asubterranean formation will return to the BHST.

Phases and Physical States

As used herein, “phase” is used to refer to a substance having achemical composition and physical state that is distinguishable from anadjacent phase of a substance having a different chemical composition ora different physical state.

As used herein, if not other otherwise specifically stated, the physicalstate or phase of a substance (or mixture of substances) and otherphysical properties are determined at a temperature of 77° F. (25° C.)and a pressure of 1 atmosphere (Standard Laboratory Conditions) withoutapplied shear.

Particles and Particulates

As used herein, a “particle” refers to a body having a finite mass andsufficient cohesion such that it can be considered as an entity buthaving relatively small dimensions. A particle can be of any sizeranging from molecular scale to macroscopic, depending on context.

A particle can be in any physical state. For example, a particle of asubstance in a solid state can be as small as a few molecules on thescale of nanometers up to a large particle on the scale of a fewmillimeters, such as large grains of sand. Similarly, a particle of asubstance in a liquid state can be as small as a few molecules on thescale of nanometers up to a large drop on the scale of a fewmillimeters. A particle of a substance in a gas state is a single atomor molecule that is separated from other atoms or molecules such thatintermolecular attractions have relatively little effect on theirrespective motions.

As used herein, particulate or particulate material refers to matter inthe physical form of distinct particles in a solid or liquid state(which means such an association of a few atoms or molecules). As usedherein, a particulate is a grouping of particles having similar chemicalcomposition and particle size ranges anywhere in the range of about 0.5micrometer (500 nm), e.g., microscopic clay particles, to about 3millimeters, e.g., large grains of sand.

A particulate can be of solid or liquid particles. As used herein,however, unless the context otherwise requires, particulate refers to asolid particulate. Of course, a solid particulate is a particulate ofparticles that are in the solid physical state, that is, the constituentatoms, ions, or molecules are sufficiently restricted in their relativemovement to result in a fixed shape for each of the particles.

It should be understood that the terms “particle” and “particulate,”includes all known shapes of particles including substantially rounded,spherical, oblong, ellipsoid, rod-like, fiber, polyhedral (such as cubicmaterials), etc., and mixtures thereof. For example, the term“particulate” as used herein is intended to include solid particleshaving the physical shape of platelets, shavings, flakes, ribbons, rods,strips, spheroids, toroids, pellets, tablets or any other physicalshape.

A particulate will have a particle size distribution (“PSD”). As usedherein, “the size” of a particulate can be determined by methods knownto persons skilled in the art.

One way to measure the approximate particle size distribution of a solidparticulate is with graded screens. A solid particulate material willpass through some specific mesh (that is, have a maximum size; largerpieces will not fit through this mesh) but will be retained by somespecific tighter mesh (that is, a minimum size; pieces smaller than thiswill pass through the mesh). This type of description establishes arange of particle sizes. A “+” before the mesh size indicates theparticles are retained by the sieve, while a “−” before the mesh sizeindicates the particles pass through the sieve. For example, −70/+140means that 90% or more of the particles will have mesh sizes between thetwo values.

Particulate materials are sometimes described by a single mesh size, forexample, 100 U.S. Standard mesh. If not otherwise stated, a reference toa single particle size means about the mid-point of theindustry-accepted mesh size range for the particulate.

Particulates smaller than about 400 U.S. Standard Mesh are usuallymeasured or separated according to other methods because small forcessuch as electrostatic forces can interfere with separating tinyparticulate sizes using a wire mesh.

The most commonly-used grade scale for classifying the diameters ofsediments in geology is the Udden-Wentworth scale. According to thisscale, a solid particulate having particles smaller than 2 mm indiameter is classified as sand, silt, or clay. Sand is a detrital grainbetween 2 mm (equivalent to 2,000 micrometers) and 0.0625 mm (equivalentto 62.5 micrometers) in diameter. (Sand is also a term sometimes used torefer to quartz grains or for sandstone.) Silt refers to particulatebetween 74 micrometers (equivalent to about −200 U.S. Standard mesh) andabout 2 micrometers. Clay is a particulate smaller than 0.0039 mm(equivalent to 3.9 μm).

As used herein, “fines” refers to solid particulates that are smallerthan most sand particulates, and generally less than about 50micrometers.

Fluids

A fluid can be a homogeneous or heterogeneous. In general, a fluid is anamorphous substance that is or has a continuous phase of particles thatare smaller than about 1 micrometer that tends to flow and to conform tothe outline of its container.

Every fluid inherently has at least a continuous phase. A fluid can havemore than one phase. The continuous phase of a treatment fluid is aliquid under Standard Laboratory Conditions. For example, a fluid can bein the form of a suspension (larger solid particles dispersed in aliquid phase), a sol (smaller solid particles dispersed in a liquidphase), an emulsion (liquid particles dispersed in another liquidphase), or a foam (a gas phase dispersed in a liquid phase).

An “oil-based” fluid means that oil is the dominant material by weightof the continuous phase of the fluid. In this context, the oil of anoil-based fluid can be any oil.

In the context of a fluid, oil is understood to refer to any kind of oilin a liquid state, whereas gas is understood to refer to a physicalstate of a substance, in contrast to a liquid. In this context, an oilis any substance that is liquid under Standard Laboratory Conditions, ishydrophobic, and soluble in organic solvents. Oils typically have a highcarbon and hydrogen content and are non-polar substances. This generaldefinition includes classes such as petrochemical oils, vegetable oils,and many organic solvents. All oils, even synthetic oils, can be tracedback to organic sources.

Solubility

The term “solution” is intended to include not only true molecularsolutions but also dispersions of a polymer wherein the polymer is sohighly hydrated as to cause the dispersion to be visually clear andhaving essentially no particulate matter visible to the unaided eye. Theterm “soluble” is intended to have a meaning consistent with thesemeanings of solution.

As used herein, a substance is considered to be “soluble” in a liquid ifat least 1 grams of the substance can be hydrated or dissolved in oneliter of the liquid when tested at 77° F. and 1 atmosphere pressure for2 hours, considered to be “insoluble” if less than 1 gram per liter, andconsidered to be “sparingly soluble” for intermediate solubility values.

As will be appreciated by a person of skill in the art, thehydratability, dispersibility, or solubility of a substance in water canbe dependent on the salinity, pH, or other substances in the water.Accordingly, the salinity, pH, and additive selection of the water canbe modified to facilitate the hydratability, dispersibility, orsolubility of a substance in aqueous solution. To the extent notspecified, the hydratability, dispersibility, or solubility of asubstance in water is determined in deionized water, at neutral pH, andwithout any other additives.

Apparent Viscosity of a Fluid

Viscosity is a measure of the resistance of a fluid to flow. In everydayterms, viscosity is “thickness” or “internal friction.” Therefore, purewater is “thin,” having a relatively low viscosity whereas honey is“thick,” having a relatively higher viscosity. Put simply, the lessviscous the fluid is, the greater its ease of movement (fluidity). Moreprecisely, viscosity is defined as the ratio of shear stress to shearrate.

A Newtonian fluid (named after Isaac Newton) is a fluid for which stressversus strain rate curve is linear and passes through the origin. Theconstant of proportionality is known as the viscosity. Examples ofNewtonian fluids include water and most gases. Newton's law of viscosityis an approximation that holds for some substances but not others.

Non-Newtonian fluids exhibit a more complicated relationship betweenshear stress and velocity gradient (i.e., shear rate) than simplelinearity. Therefore, there exist a number of forms of non-Newtonianfluids. Shear thickening fluids have an apparent viscosity thatincreases with increasing the rate of shear. Shear thinning fluids havea viscosity that decreases with increasing rate of shear. Thixotropicfluids become less viscous over time at a constant shear rate.Rheopectic fluids become more viscous over time at a constant shearrate. A Bingham plastic is a material that behaves as a solid at lowstresses but flows as a viscous fluid at high yield stresses.

Most fluids are non-Newtonian fluids. Accordingly, the apparentviscosity of a fluid applies only under a particular set of conditionsincluding shear stress versus shear rate, which must be specified orunderstood from the context. As used herein, a reference to viscosity isactually a reference to an apparent viscosity. Apparent viscosity iscommonly expressed in units of mP·s or centipoise (cP), which areequivalent.

Like other physical properties, the viscosity of a Newtonian fluid orthe apparent viscosity of a non-Newtonian fluid may be highly dependenton the physical conditions, primarily temperature and pressure.

Viscosity Measurements

There are numerous ways of measuring and modeling viscous properties,and new developments continue to be made. The methods depend on the typeof fluid for which viscosity is being measured. A typical method forquality assurance or quality control (QA/QC) purposes uses a couettedevice, such as a FANN™ Model 35 or Model 50 viscometer or a CHANDLER™Model 5550 HPHT viscometer. Such a viscometer measures viscosity as afunction of time, temperature, and shear rate. The viscosity-measuringinstrument can be calibrated using standard viscosity silicone oils orother standard viscosity fluids.

Due to the geometry of most common viscosity-measuring devices, however,solid particulate, especially if larger than silt (larger than 74micron), would interfere with the measurement on some types of measuringdevices. Therefore, the viscosity of a fluid containing such solidparticulate is usually inferred and estimated by measuring the viscosityof a test fluid that is similar to the fracturing fluid without anyproppant or gravel that would otherwise be included. However, assuspended particles (which can be solid, gel, liquid, or gaseousbubbles) usually affect the viscosity of a fluid, the actual viscosityof a suspension is usually somewhat different from that of thecontinuous phase.

In general, a FANN™ Model 35 viscometer is used for viscositymeasurements of less than about 30 mP·s (cP). The Model 35 does not havetemperature and pressure controls, so it is used for fluids at ambientconditions (that is, Standard Laboratory Conditions). However, with anoptional heating cup, viscosity can be measured at higher temperaturesso long as the temperature is below the boiling point of the solvent.Except to the extent otherwise specified, the apparent viscosity of afluid having a viscosity of less than about 30 cP (excluding anysuspended solid particulate larger than silt) is measured with a FANN™Model 35 type viscometer with a bob and cup geometry using an R1 rotor,B1 bob, and F1 torsion spring at a shear rate of 511 sec⁻¹ (300 rpm) andat a temperature of 77° F. (25° C.) and a pressure of 1 atmosphere.

Permeability

Permeability refers to how easily fluids can flow through a material.For example, if the permeability is high, then fluids will flow moreeasily and more quickly through the material. If the permeability islow, then fluids will flow less easily and more slowly through thematerial. As used herein, unless otherwise specified, permeability ismeasured with light oil having an API gravity of greater than 31.1degrees.

For gas wells, “high permeability” means the matrix of a subterraneanformation has a permeability of at least 10 millidarcy (mD) and “lowpermeability” means the matrix has a permeability of less than 1 mD. Foroil wells, “high permeability” means the matrix of a subterraneanformation has a permeability of at least 30 mD and “low permeability”means the matrix has a permeability of less than 10 mD. For gravelpacking, “high permeability” means the matrix of a subterraneanformation has a permeability of at least 500 mD and “low permeability”means the matrix has a permeability of less than 50 mD.

General Approach

A composition for treating a zone of a subterranean formation penetratedby a wellbore may include various components. In certain embodiments,the treatment fluid may include a combined first solution and secondsolution.

The first solution may include at least one amine containing resin. Invarious embodiments, the at least one amine containing resin may beselected from: primary, secondary, tertiary amines, and combinationsthereof. In certain embodiments, the at least one amine containing resinmay include a silane-based amine in which the silicon atom has only oneamine functionality and at least one alkoxy group attached to thesilicon atom. The alkoxy group on the silicon atom may assist with themolecule attaching to a surface of a fine/sand. Without being limited byan particular theory, it is believed that an amine functionality on afirst chemical may bond with an epoxy group on a second chemical and theother side of the first chemical may form a bond with a fine/sandsurface. For example, the at least one amine containing resin may beselected from: aliphatic amines, cycloaliphatic amines, heterocyclicamines, amidoamines, and combinations thereof. In various embodiments,the at least one amine containing resin may be selected from:triethylenetetraamine, ethylenediamine, N-cocoalkyltrimethylenediamine,isophoronediamine, and combinations thereof. In certain embodiments, theat least one amine containing resin may be selected from: trimethoxysilyl propyl ethelene diamine, N-[3(trimethoxysilyl)propyl]ethylenediamine], 3-aminopropyltriethoxysilane,3-aminopropyltrimethoxysilane, 4-aminobutyltriethoxysilane,aminophenyltrimehtoxysilane,3-aminopropyltris(methoxyethoxy-ethoxy)silane,11-aminodecyltriethoxysilane, 2-(4-pyridylethyl)triethoxysilane,3-aminopropyl diisopropylethoxysilane, 3-aminopropyldimethylethoxysilane, N-(2-aminoethyl)-3-aminopropyl-triethoxysilane,N-(6-aminohexyl)aminomethyl-triethoxysilane,N-(6-aminohexyl)aminopropyl-trimethoxysilane, (3trimethoxysilylpropyl)diethylene triamine, nbutylaminopropyltrimethoxysilane, bis(2hydroxyethyl)-3-aminopropyl-triethoxysilane, 3 (Nstyrylmethyl-2-aminoethylamino)propyltrimethoxysilane hydrochloride, andcombinations thereof.

The at least one amine containing resin, such as a silane-based amine,may not have any other type of functional group that would be subject torapid hydrolysis or free-radical polymerization under the designconditions, which would make the molecule excessively reactive duringplacement. In certain embodiments, the at least one amine containingresin may have a concentration of approximately 1% to approximately 3%v/v of the continuous phase of the treatment fluid.

The second solution may include at least one epoxide containing resin.Selection of a suitable epoxide containing resin may be affected by thetemperature of the subterranean formation to which the fluid will beintroduced. In certain embodiments, the second chemical may have onlyone epoxy group to avoid polymerization and formation of an epoxy resin.In certain embodiments, the second chemical may be a silane-basedcompound with only one epoxy group on silicon atom and a minimum of onealkoxy group on silicon atom. Without being limited by any particulartheory, it is believed that the alkoxy group on the silicon atom mayhelp the molecule to attach the surface of a fine/sand. Examples ofepoxide containing resins that can be used include, but are not limitedto, glycidoxy propyl trimethoxy silane, (3glycidoxypropyl)trimethoxysilane, (3 glycidoxypropyl)triethoxysilane,5,6 epoxyhexyltriethoxysilane, (3 glycidoxypropyl)methyldiethoxysilane,(3 glycidoxypropyl)methyldimethoxysilane, (3glycidoxypropyl)dimethylethoxysilane, and combinations thereof.

The at least one epoxide containing resin may not have any other type offunctional group that would be subject to rapid hydrolysis orfree-radical polymerization under the design conditions, which wouldmake the molecule excessively reactive during placement. In certainembodiments, the at least one epoxide containing resin may have aconcentration of approximately 2% to approximately 5% v/v of thecontinuous phase of the treatment fluid.

The first solution may also include citraconic anhydride. Citraconicanhydride (CAS No 616-02-4) is a chemical with the following formula:

Citraconic anhydride may delay a chemical reaction between amine andepoxy by temporarily converting amine to amide. The citraconic anhydridemay delay a crosslinking reaction between the at least one aminecontaining resin and the at least one epoxide containing resin. Whilenot being limited by any particular theory, the citraconic anhydride mayprotect the amine group of the at least one amine containing resin fromreaction with the epoxides of the at least one epoxide containing resinby reversibly converting amine to amide.

Citraconic anhydride may be added to a solution including the at leastone amine containing resin to form the first solution. Citraconicanhydride may be added in quantities such that the pH of the firstsolution is between approximately 8.0 and approximately 9.0. In certainembodiments, the pH of the first solution may be approximately 8.5.

Continuous Phase

In various embodiments, the treatment fluid comprises a continuous phasethat is aqueous, and wherein the at least one amine containing resin andthe at least one epoxide containing resin are dissolved or dispersed inthe continuous phase.

In various embodiments, the treatment fluid may include less than 10% byweight of a resin. In certain embodiments, the treatment fluid includesless than 1% by weight of any resin. Any resin that may be presentshould not adversely affect the purposes of the treatment fluid ordamage the subterranean formation. In certain embodiments, the treatmentfluid does not include any resin.

In various embodiments of methods according to the disclosure, thetreatment fluid has a viscosity of less than 5 cP measured at a shearrate of 511 sec⁻¹. In various embodiments of methods according to thedisclosure, the treatment fluid has a viscosity of approximately 1 cPmeasured at a shear rate of 511 sec⁻¹.

The methods according to the disclosure can stabilize the formationparticulates of sand and fines by agglomerating the particulates in theformation, thereby preventing the fines from migrating. It is believedthat the agglomeration does not substantially reduce the permeability ofthe subterranean formation or damage the subterranean formation.

The term “regain permeability” refers to the percentage of permeabilityof a portion of a subterranean formation following treatment; that is,it is a percentage of the post-treatment permeability as compared to thepre-treatment permeability. In some embodiments, the methods of thepresent disclosure are able to achieve a regain permeability of at leastabout 60%, which is considered a good regain permeability. In someembodiments, the methods of the present disclosure are able to achieve aregain permeability of at least about 85%. In some embodiments, themethods of the present disclosure are able to achieve a regainpermeability of at least about 90%. In some embodiments of the presentdisclosure, the regain permeability is at least about 95%.

The various embodiments of methods of the present disclosure are capableof substantially stabilizing the particulates such that loose or weaklyconsolidated particulates are prevented from shifting or migrating oncethe treatment is complete. This is particularly significant in thecontext of portions of formations where it is desirable to control theparticulates without having to use a gravel pack. In such situations,the methods of the present disclosure including the use of a screen orliner (which may be an expandable or traditional screen or a perforatedor slotted liner, or any similar device known in the art) can act tocontrol particulates to a sufficiently high degree that a gravel packbecomes unnecessary.

Thus, according to the embodiments of the present disclosure thatinclude the use of both a treatment fluid according to the disclosureand a mechanical sand control device such as a screen or liner, themethods create a stable, permeable region around the wellbore thatresists particulate migration. The screen or liner can be used, forexample, to provide mechanical support to prevent borehole collapse.Such embodiments may make the use of screen-only or liner-only (nogravel pack) completions functional over a much wider range of formationproperties than previously thought possible.

In addition, the methods can be used by applying the consolidationtreatment fluid to transform low quality sand into competent proppantmaterials. Curable resins, agglomerating agents, or surface modificationagents may be used to provide a film of coating on the low-quality sand,encapsulating the grains such that fines generated when the grains arecrushed as a result of high stress load applied may be locked in place,mitigating their migration within the proppant pack, thus minimizing itspermeability damage. See exemplary process below.

In addition, the methods can be used as a remedial treatment to beinjected into a treatment zone through a proppant or gravel pack of apreviously performed fracturing treatment or gravel pack.

The treatment may first involve the injection of one or more pre-flushfluids to remove hydrocarbons or debris from the surfaces of theformation sand for preconditioning these surfaces for accept the coatingof the consolidating treatment fluid. The pre-flush fluid(s) may or maynot contain one or more surfactants to enhance the wetting of theconsolidating treatment fluid onto the surfaces of the formation sandparticulates.

A post-flush fluid may be injected behind the treatment fluid todisplace the treatment fluid completely from the wellbore and penetratea distance (i.e., from 1 to 4 wellbore diameters) into the formations,as well as to displace excess consolidation treatment fluid from thepore spaces between formation sand grains. An aqueous based fluid or anon-aqueous fluid can be used as the post-flush fluid.

After the injection of post-flush fluid, the well may be shut in for aperiod of time depending on the bottomhole temperature of the well toallow the consolidation treatment fluid to react and transform theformation sand into a permeable, consolidated sand pack.

In another embodiment, rather than a single mixture of the firstsolution and the second solution, each component may be injectedindividually.

The injection rate of consolidation treatment is typically maintainedless than that of fracture gradient to prevent generation offracture(s).

The methods can be performed in vertical, inclined, or horizontalwellbores, and in open-hole or under-reamed completions as well as incased wells. If a method is to be carried out in a cased wellbore, thecasing is perforated to provide for fluid communication with a zone ofinterest in the subterranean formation.

The methods can optionally include the step of: before or after the stepof introducing the treatment fluid, introducing a fracturing fluid intothe wellbore at a pressure sufficient to create at least one fracture inthe subterranean formation. For example, the composition can be used asa prior treatment to hydraulic fracturing.

Treatment Zone

In certain embodiments, the treatment zone is an unconsolidated orweakly consolidated subterranean formation. In certain embodiments, thetreatment zone is in a subterranean formation having loose particulateof silicon dioxide such as sand or quartz particles. For example, thesubterranean formation can be a sandstone formation. In certainembodiments, the sandstone formation has at least 70% sandstone materialby weight. The formation may include some clay, as the siloxane may bondwith the surface of a clay, but if clay is present in more than about5%, the formation may undesirably swell in the presence of water or 3%aqueous KCl.

The subterranean formation can be, for example, a gas reservoir having apermeability greater than about 5 mD. By way of another example, thesubterranean formation can be an oil reservoir having a permeabilitygreater than about 20 mD.

Mechanical Sand Control Device

In various embodiments, additionally comprising, before or afterintroducing the treatment fluid into the zone, installing a mechanicalsand control device in the wellbore of the zone.

In certain embodiments, the mechanical sand control device is selectedfrom the group consisting of: a perforated liner, a slotted pipe, awire-wrapped screen, a non-expandable screen, and an expandable screen.

In certain embodiments, the mechanical sand control device is not gravelpacked.

Methods

Certain embodiments may include a method of treating a zone of asubterranean formation penetrated by a wellbore. Methods may includeforming a treatment fluid as described herein. The treatment fluid maybe introduced through the wellbore into the zone of the subterraneanformation surrounding the wellbore.

In certain embodiments, the amide of the treatment fluid may beconverted back to amine by lowering the pH in the zone of thesubterranean formation. pH may be lowered by in-situ generation of weakacids and/or providing a pH adjusting fluid into the zone of thesubterranean formation surrounding the wellbore. In certain embodiments,the pH may be lowered at least to a level that a portion of the amidefunctionality on the at least one amine containing resin is convertedback to an amine functionality. In certain embodiments, the pH may belowered to approximately 3.0 to approximately 5.0. In certainembodiments, the pH adjusting fluid may be acetic acid, formic acid, oneor more buffering agents, and combinations thereof.

Optional Steps

In various embodiments, the methods can optionally or advantageouslyinclude additional steps.

For example, the treatment zone and job conditions can be selected suchthat the design temperature is in the range of about 30° C. to about200° C.

A method according to the disclosure can include a step of, prior tointroducing the treatment fluid: isolating a zone of interest in thesubterranean formation.

A treatment fluid can be prepared at the job site.

In certain embodiments, the preparation of a fluid can be done at thejob site in a method characterized as being performed “on the fly.” Theterm “on-the-fly” is used herein to include methods of combining two ormore components wherein a flowing stream of one element is continuouslyintroduced into flowing stream of another component so that the streamsare combined and mixed while continuing to flow as a single stream aspart of the on-going treatment. Such mixing can also be described as“real-time” mixing.

Often the step of delivering a fluid into a well is within a relativelyshort period after forming the fluid, e.g., less within 30 minutes toone hour. In certain embodiments, the step of delivering the fluid isimmediately after the step of forming the fluid, which is “on the fly.”

It should be understood that the step of delivering a treatment fluidinto a well can advantageously include the use of one or more fluidpumps.

In an embodiment, the step of introducing is at a rate and pressurebelow the fracture pressure of the treatment zone. For example, thetreatment fluid is introduced to the subterranean formation at a matrixflow rate. That is, the composition is added at such a rate that it isable to penetrate the formation without substantially affecting thestructure of the formation sands or proppant or gravel matrixes itencounters.

In an embodiment, the step of introducing a treatment comprisesintroducing under conditions for fracturing a treatment zone. The fluidis introduced into the treatment zone at a rate and pressure that are atleast sufficient to fracture the zone.

The step of introducing the treatment fluid can be performed eitherbefore or after the sand screen installation or gravel packing arecompleted. It is beneficial to provide a method that transforms smallformation sand or fines into larger aggregates. In certain embodiments,this does not reduce permeability of the formation, and the permeabilitymay be increased. This enhances the retention of fines behind the screenwithout plugging or eroding it.

After the step of introducing a treatment, the zone may be shut in. Thismay occur with time under the temperature, pressure, and otherconditions in the zone.

The methods can include a step of: after the steps of shutting in andinstalling the mechanical sand control device, producing fluid from thesubterranean formation through the mechanical sand control device.

In certain embodiments, the step of shutting in is for at least asufficient time for at least 50% by weight of the amine functionality toreact with the epoxide functionality in the treatment zone under thedesign conditions.

In various embodiments, the methods additionally comprising flowing backor producing from the zone without gravel packing the mechanical sandcontrol device.

In certain embodiments, after any such well treatment, a step ofproducing hydrocarbon from the subterranean formation is the desirableobjective and an additional step according to the method.

Example

To facilitate a better understanding of the present disclosure, thefollowing examples of certain aspects of some embodiments are given. Inno way should the following examples be read to limit, or define, theentire scope of the disclosure.

Core flow tests were carried out on a sandpack simulating anunconsolidated subterranean formation to evaluate the effectiveness oftreatment with a treatment fluid according to the disclosure.

A treatment fluid was prepared. The treatment fluid included a mixtureof:

1. Solution A—Amine containing resin+an amount of citraconic anhydrideto create a pH 8.5 for Solution A

2. Solution B—Epoxide containing resin

Test Procedure:

Sandpack was prepared using 88% course silica flour (SSA-2™ availablefrom Halliburton Energy Services, Duncan, Okla.), 10% fluid lossadditive (WAC-9™ available from Halliburton Energy Services, Duncan,Okla.), and bentonite clay (2%), with additional layers of 20/40 sand(about 1 cm) at both ends. The fluid loss additive is added to get anon-homogeneity of the sand pack to represent an unconsolidatedformation. The two ends of the sandpack were closed using 300 meshscreens and 20/40 mesh. The sandpack was initially saturated with 3% KClaqueous solution and initial permeability of the sandpack to the 3% KClsolution was determined.

The treatment fluid (Solution A+Solution B) was pumped through thesandpack.

A pH adjusting fluid was pumped through the sandpack.

The sandpack was shut in for 24 to 72 hours at 185° F.

After a predetermined time, final permeability and unconfinedcompressive strength (UCS) were determined after the curing period.After complete curing the core was extruded from the brass sample celland cut into a core sample size and then unconfined compressive strengthwas measured immediately. Good compressive strength was observed.

Observation:

A good regained permeability and unconfined compressive strength wasfound. Therefore, it was determined that the treatment fluid would notdamage a subterranean formation.

CONCLUSION

Therefore, the present disclosure is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein.

The exemplary methods and compositions disclosed herein may directly orindirectly affect one or more components or pieces of equipmentassociated with the preparation, delivery, recapture, recycling, reuse,and/or disposal of the disclosed compositions. For example, and withreference to FIG. 1, the disclosed methods and compositions may directlyor indirectly affect one or more components or pieces of equipmentassociated with an exemplary fracturing system 10, according to one ormore embodiments. In certain instances, the system 10 includes afracturing fluid producing apparatus 20, a fluid source 30, a proppantsource 40, and a pump and blender system 50 and resides at the surfaceat a well site where a well 60 is located. In certain instances, thefracturing fluid producing apparatus 20 combines a gel pre-cursor withfluid (e.g., liquid or substantially liquid) from fluid source 30, toproduce a hydrated fracturing fluid that is used to fracture theformation. The hydrated fracturing fluid can be a fluid for ready use ina fracture stimulation treatment of the well 60 or a concentrate towhich additional fluid is added prior to use in a fracture stimulationof the well 60. In other instances, the fracturing fluid producingapparatus 20 can be omitted and the fracturing fluid sourced directlyfrom the fluid source 30. In certain instances, the fracturing fluid maycomprise water, a hydrocarbon fluid, a polymer gel, foam, air, wet gasesand/or other fluids.

The proppant source 40 can include a proppant for combination with thefracturing fluid. The system may also include additive source 70 thatprovides one or more additives (e.g., gelling agents, weighting agents,and/or other optional additives) to alter the properties of thefracturing fluid. For example, the other additives 70 can be included toreduce pumping friction, to reduce or eliminate the fluid's reaction tothe geological formation in which the well is formed, to operate assurfactants, and/or to serve other functions.

The pump and blender system 50 receives the fracturing fluid andcombines it with other components, including proppant from the proppantsource 40 and/or additional fluid from the additives 70. The resultingmixture may be pumped down the well 60 under a pressure sufficient tocreate or enhance one or more fractures in a subterranean zone, forexample, to stimulate production of fluids from the zone. Notably, incertain instances, the fracturing fluid producing apparatus 20, fluidsource 30, and/or proppant source 40 may be equipped with one or moremetering devices (not shown) to control the flow of fluids, proppants,and/or other compositions to the pumping and blender system 50. Suchmetering devices may permit the pumping and blender system 50 can sourcefrom one, some or all of the different sources at a given time, and mayfacilitate the preparation of fracturing fluids in accordance with thepresent disclosure using continuous mixing or “on-the-fly” methods.Thus, for example, the pumping and blender system 50 can provide justfracturing fluid into the well at some times, just proppants at othertimes, and combinations of those components at yet other times.

FIG. 2 shows the well 60 during a fracturing operation in a portion of asubterranean formation of interest 102 surrounding a well bore 104. Thewell bore 104 extends from the surface 106, and the fracturing fluid 108is applied to a portion of the subterranean formation 102 surroundingthe horizontal portion of the well bore. Although shown as verticaldeviating to horizontal, the well bore 104 may include horizontal,vertical, slant, curved, and other types of well bore geometries andorientations, and the fracturing treatment may be applied to asubterranean zone surrounding any portion of the well bore. The wellbore 104 can include a casing 110 that is cemented or otherwise securedto the well bore wall. The well bore 104 can be uncased or includeuncased sections. Perforations can be formed in the casing 110 to allowfracturing fluids and/or other materials to flow into the subterraneanformation 102. In cased wells, perforations can be formed using shapecharges, a perforating gun, hydro jetting and/or other tools.

The well is shown with a work string 112 depending from the surface 106into the well bore 104. The pump and blender system 50 is coupled a workstring 112 to pump the fracturing fluid 108 into the well bore 104. Theworking string 112 may include coiled tubing, jointed pipe, and/or otherstructures that allow fluid to flow into the well bore 104. The workingstring 112 can include flow control devices, bypass valves, ports, andor other tools or well devices that control a flow of fluid from theinterior of the working string 112 into the subterranean zone 102. Forexample, the working string 112 may include ports adjacent the well borewall to communicate the fracturing fluid 108 directly into thesubterranean formation 102, and/or the working string 112 may includeports that are spaced apart from the well bore wall to communicate thefracturing fluid 108 into an annulus in the well bore between theworking string 112 and the well bore wall.

The working string 112 and/or the well bore 104 may include one or moresets of packers 114 that seal the annulus between the working string 112and well bore 104 to define an interval of the well bore 104 into whichthe fracturing fluid 108 will be pumped. FIG. 2 shows two packers 114,one defining an uphole boundary of the interval and one defining thedownhole end of the interval. When the fracturing fluid 108 isintroduced into well bore 104 (e.g., in FIG. 2, the area of the wellbore 104 between packers 114) at a sufficient hydraulic pressure, one ormore fractures 116 may be created in the subterranean zone 102. Theproppant particulates in the fracturing fluid 108 may enter thefractures 116 where they may remain after the fracturing fluid flows outof the well bore. These proppant particulates may “prop” fractures 116such that fluids may flow more freely through the fractures 116.

While not specifically illustrated herein, the disclosed methods andcompositions may also directly or indirectly affect any transport ordelivery equipment used to convey the compositions to the fracturingsystem 10 such as, for example, any transport vessels, conduits,pipelines, trucks, tubulars, and/or pipes used to fluidically move thecompositions from one location to another, any pumps, compressors, ormotors used to drive the compositions into motion, any valves or relatedjoints used to regulate the pressure or flow rate of the compositions,and any sensors (i.e., pressure and temperature), gauges, and/orcombinations thereof, and the like.

The particular embodiments disclosed above are illustrative only, as thepresent disclosure may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. It is, therefore, evident that theparticular illustrative embodiments disclosed above may be altered ormodified and all such variations are considered within the scope of thepresent disclosure.

The various elements or steps according to the disclosed elements orsteps can be combined advantageously or practiced together in variouscombinations or sub-combinations of elements or sequences of steps toincrease the efficiency and benefits that can be obtained from thedisclosure.

It will be appreciated that one or more of the above embodiments may becombined with one or more of the other embodiments, unless explicitlystated otherwise.

The illustrative disclosure can be practiced in the absence of anyelement or step that is not specifically disclosed or claimed.

Furthermore, no limitations are intended to the details of construction,composition, design, or steps herein shown, other than as described inthe claims.

All numbers and ranges disclosed above may vary by some amount. Whenevera numerical range with a lower limit and an upper limit is disclosed,any number and any included range falling within the range isspecifically disclosed. In particular, every range of values (of theform, “from about a to about b,” or, equivalently, “from approximately ato b,” or, equivalently, “from approximately a-b”) disclosed herein isto be understood to set forth every number and range encompassed withinthe broader range of values.

Although the foregoing description is directed to the preferredembodiments of the disclosure, it is noted that other variations andmodifications will be apparent to those skilled in the art, and may bemade without departing from the spirit or scope of the disclosure.Moreover, features described in connection with one embodiment of thedisclosure may be used in conjunction with other embodiments, even ifnot explicitly stated above.

What is claimed is:
 1. A method of treating a zone of a subterraneanformation penetrated by a wellbore, the method comprising: (A) forming atreatment fluid comprising: (i) a first solution comprising: (a) atleast one amine containing resin; and (b) citraconic anhydride; (ii) asecond solution comprising at least one epoxide containing resin; and(B) introducing the treatment fluid through the wellbore into the zoneof the subterranean formation surrounding the wellbore.
 2. The method ofclaim 1, wherein the at least one amine containing resin is selectedfrom the group consisting of: trimethoxy silyl propyl ethelene diamine,N-[3 (trimethoxysilyl)propyl]ethylenediamine],3-aminopropyltriethoxysilane, 3-aminopropyltrimethoxysilane,4-aminobutyltriethoxysilane, aminophenyltrimehtoxysilane,3-aminopropyltris(methoxyethoxy-ethoxy)silane,11-aminodecyltriethoxysilane, 2-(4-pyridylethyl)triethoxysilane,3-aminopropyl diisopropylethoxysilane, 3-aminopropyldimethylethoxysilane, N-(2-aminoethyl)-3-aminopropyl-triethoxysilane,N-(6-aminohexyl)aminomethyl-triethoxysilane,N-(6-aminohexyl)aminopropyl-trimethoxysilane, (3trimethoxysilylpropyl)diethylene triamine, nbutylaminopropyltrimethoxysilane, bis(2hydroxyethyl)-3-aminopropyl-triethoxysilane, 3 (Nstyrylmethyl-2-aminoethylamino)propyltrimethoxysilane hydrochloride, andcombinations thereof.
 3. The method of claim 2, wherein the at least oneamine containing resin is trimethoxy silyl propyl ethelene diamine. 4.The method of claim 1, wherein the first solution has a pH betweenapproximately 8.0 and approximately 9.0.
 5. The method of claim 4,wherein the first solution has a pH of approximately 8.5.
 6. The methodof claim 1, wherein citraconic anhydride is present in the firstsolution in an amount such that the pH of the first solution has a pHbetween approximately 8.0 and approximately 9.0.
 7. The method of claim1, wherein the at least one epoxy containing resin is selected from thegroup consisting of: glycidoxy propyl trimethoxy silane, (3glycidoxypropyl)trimethoxysilane, (3 glycidoxypropyl)triethoxysilane,5,6 epoxyhexyltriethoxysilane, (3 glycidoxypropyl)methyldiethoxysilane,(3 glycidoxypropyl)methyldimethoxysilane, (3glycidoxypropyl)dimethylethoxysilane, and combinations thereof.
 8. Themethod of claim 7, wherein the at least one epoxy containing resin isglycidoxy propyl trimethoxy silane.
 9. The method of claim 1, furthercomprising converting amide in the treatment fluid to amine by loweringpH by in-situ generation of weak acids.
 10. The method of claim 1,further comprising converting amide in the treatment fluid to amine byproviding a pH adjusting fluid into the zone of the subterraneanformation surrounding the wellbore.
 11. The method of claim 1, furthercomprising mixing the treatment fluid using mixing equipment.
 12. Themethod of claim 1, wherein the treatment fluid is introduced into thesubterranean formation using one or more pumps.
 13. A composition fortreating a zone of a subterranean formation penetrated by a wellbore,the composition comprising: (A) a first solution comprising: (i) atleast one amine containing resin; and (ii) citraconic anhydride; (B) asecond solution mixed with the first solution, the second solutioncomprising at least one epoxide containing resin.
 14. The composition ofclaim 13, wherein the at least one amine containing resin is selectedfrom the group consisting of: trimethoxy silyl propyl ethelene diamine,N-[3 (trimethoxysilyl)propyl]ethylenediamine],3-aminopropyltriethoxysilane, 3-aminopropyltrimethoxysilane,4-aminobutyltriethoxysilane, aminophenyltrimehtoxysilane,3-aminopropyltris(methoxyethoxy-ethoxy)silane,11-aminodecyltriethoxysilane, 2-(4-pyridylethyl)triethoxysilane,3-aminopropyl diisopropylethoxysilane, 3-aminopropyldimethylethoxysilane, N-(2-aminoethyl)-3-aminopropyl-triethoxysilane,N-(6-aminohexyl)aminomethyl-triethoxysilane,N-(6-aminohexyl)aminopropyl-trimethoxysilane, (3trimethoxysilylpropyl)diethylene triamine, nbutylaminopropyltrimethoxysilane, bis(2hydroxyethyl)-3-aminopropyl-triethoxysilane, 3 (Nstyrylmethyl-2-aminoethylamino)propyltrimethoxysilane hydrochloride, andcombinations thereof.
 15. The composition of claim 14, wherein the atleast one amine containing resin is trimethoxy silyl propyl ethelenediamine.
 16. The composition of claim 13, wherein the first solution hasa pH between approximately 8.0 and approximately 9.0.
 17. Thecomposition of claim 16, wherein the first solution has a pH ofapproximately 8.5.
 18. The composition of claim 13, wherein citraconicanhydride is present in the first solution in an amount such that the pHof the first solution has a pH between approximately 8.0 andapproximately 9.0.
 19. The composition of claim 13, wherein the at leastone epoxy containing resin is selected from the group consisting of:glycidoxy propyl trimethoxy silane, (3 glycidoxypropyl)trimethoxysilane,(3 glycidoxypropyl)triethoxysilane, 5,6 epoxyhexyltriethoxysilane, (3glycidoxypropyl)methyldiethoxysilane, (3glycidoxypropyl)methyldimethoxysilane, (3glycidoxypropyl)dimethylethoxysilane, and combinations thereof.
 20. Thecomposition of claim 19, wherein the at least one epoxy containing resinis glycidoxy propyl trimethoxy silane.